Formation wettability has been the object of a substantial amount of research for the last forty years or so, primarily because of its impact on saturation and recovery estimates. Wettability describes how two immiscible fluids adhere to a solid. For reservoir rocks, wettability plays a major role in defining how hydrocarbon and water coexist in the pores and, therefore, influence numerous properties such as capillary pressure, relative permeability, water flood behavior and electrical properties and enhanced recovery.
Wettability strongly affects any parameter related to two-phase fluid displacement. An example is relative permeability, a major determinant in primary oil production and water floods. In uniformly wetted formations, the relative permeability to one fluid increases as the system becomes more wetted by the other fluid. In other words, permeability to the non-wetting fluid increases because the fluid is not "bound" to the pore surfaces and, therefore, becomes more mobile.
Another parameter affected by wettability is irreducible water saturation, which reaches a minimum in formations with near-neutral wettability. The irreducible water saturation level is the level above which the water of the formation will not flow. In fractionally-wet formations, irreducible water saturation also depends on the distribution and total area of water and oil-wet surfaces. Wettability also contributes to the dynamics of a water flood. In strongly water-wet formations, oil recovery is initially high but tapers off dramatically after breakthrough. In strongly oil-wet formations, breakthrough occurs early but production continues for a long time afterward.
Various methods, both quantitative and qualitative, are presently used to determine wettability. Major quantitative methods include the contact angle method, the Amott method, and the U.S. Bureau of Mines (USBM) method. All of these methods are described in, Wettability Literature Survey--Part 2: Wettability Measurement, William G. Anderson, Journal of Petroleum Technology, Nov. 1986, pages 1246-1262, which is incorporated herein by reference.
For pure materials, there are standard techniques for measuring the contact angle. But for rocks, or formations, the contact angle cannot take into account the heterogeneity of the rock surface. For example, a rough-surfaced rock causes the apparent contact angle to depart dramatically from the contact angle measured on a smooth surface. Contact angle measurements are difficult in porous media and so far impossible to obtain in situ. Other methods to characterize the wettability have been developed. They are based on capillary pressure measurements and involve laboratory analysis of a core sample--not in situ measurements. Laboratory measurements of wettability require considerable care in preserving and reproducing in situ conditions of the core samples. While the contact angle measurement 0 quantifies wettability for a specific surface, the two other methods (Amott and USBM), have been developed for gauging average wettability in oil field cores. Both use parts of the capillary pressure curve, a standard petrophysical laboratory measurement. Capillary pressure curves are obtained while draining (extracting the wetting phase), and imbibing (injecting the wetting phase). Imbibition begins spontaneously and is then forced.
The Amott method uses the spontaneous and forced-imbibition parts of the capillary curves. In this method, two ratios are compared in order to give wettability. One ratio is the volume of water imbibed spontaneously, divided by the total volume of water imbibed both spontaneously and forced. The core is initially centrifuged in oil to irreducible water saturation. The second ratio is similarly defined for oil imbibition, the core being initially centrifuged in water. Comparing these ratios tends to suppress effects of viscosity, permeability, and initial saturation. A limitation of the method is that it relies on spontaneous imbibition of the wetting fluid displacing the non-wetting fluid. This makes it adequate for measuring wettability for strongly water-wet and oil-wet formations, but not in neutrally wet formations.
The United States Bureau of Mines (USBM) method uses the drainage and forced-imbibition parts of the capillary pressure curves for determining a so-called Wettability Index. The work required by each fluid to displace the other is indicated by the areas under the curves--for oil driving water and for water driving oil. The Wettability Index is expressed as the logarithm of the ratio of the areas under the plotted capillary curves. If the index is greater than zero the formation is water-wet; if it is less than zero the formation is oil-wet; and if it is zero the formation is neutrally wet. Consequently, the USBM method has increased sensitivity in the neutral-wettability range because it does not depend on spontaneous imbibition. Nevertheless, neither the Amott nor the USBM methods are used to make measurements in situ within a borehole.
While much work has been done on developing new techniques and tools for determining the wettability of a formation, there is still much work that needs to be done. For example, until only a few years ago, oil-wet formations were considered a rare curiosity. But using advanced techniques of core handling and analysis, it was found that as many as half of the formations were either strongly oil-wet or of mixed or of fractional wettability.
Downhole test tools have been used for extracting fluid from a borehole well and measuring the fluid pressure during and after the flow into a chamber to get the flowing and static formation pressure. However, they do not perform a series of fluid drawings and re-injections.
Consequently, there still exists a substantial need as art for improved methods and formation test tools which can make in situ measurements in a borehole to determine wettability of a formation, particularly in zones of irreducible water saturation; that is, the zones above the oil water contact.